Note: Descriptions are shown in the official language in which they were submitted.
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METHODS FOR OPTIMIZING AND MONITORING
UNDERGROUND DRILLING
Statement of Related Applications
[0001] This application claims priority to U.S. Provisional Application
Serial No. 13/283,518, filed October 27, 2011, which is hereby incorporated by
reference in its entirety.
Field of the Invention
[0002] The present invention relates to underground drilling, and more
specifically to methods for optimizing and monitoring such a drilling
operation.
Background of the Invention and Related Art
[0003] Underground drilling, such as gas, oil, or geothermal drilling,
generally involves drilling a bore through a formation deep in the earth. Such
bores
are formed by connecting a drill bit to long sections of pipe, referred to as
a "drill
pipe," so as to form an assembly commonly referred to as a "drill string." The
drill
string extends from the surface to the bottom of the bore.
[0004] The drill bit is rotated so that the drill bit advances into the earth,
thereby forming the bore. In rotary drilling, the drill bit is rotated by
rotating the drill
string at the surface. Piston-operated pumps on the surface pump high-pressure
fluid,
referred to as "drilling mud," through an internal passage in the drill string
and out
through the drill bit. The drilling mud lubricates the drill bit, and flushes
cuttings
from the path of the drill bit. In the case of motor drilling, the flowing mud
also
powers a drilling motor, commonly referred to as a "mud motor," which turns
the bit,
whether or not the drill string is rotating. The mud motor is equipped with a
rotor that
generates a torque in response to the passage of the drilling mud
therethrough. The
rotor is coupled to the drill bit so that the torque is transferred to the
drill bit, causing
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the drill bit to rotate. The drilling mud then flows to the surface through an
annular
passage formed between the drill string and the surface of the bore.
[0005] Typically, measurements are taken of various operating parameters
during drilling. For example, surface equipment senses the rate of penetration
of the
drill bit into the formation, the rotational speed of the drill string, the
hook load,
surface torque, and pressure. Sensors either at the surface or in a bottom
hole
assembly, or both, measure the axial tensile/compression load, torque and
bending.
However, selecting the values of the drilling parameters that will result in
optimum
drilling is a difficult task. For example, although reducing the downhole
force applied
to the drill bit, commonly referred to as the "weight on bit" ("WOB") or the
rotary
speed of the drill bit may reduce vibration, and thereby extend the life of
drill string
components, it may also reduce the rate of penetration ("ROP"). In general,
optimal
drilling is obtained when the rate of penetration of the drill bit into the
formation is as
high as possible while the vibration is as low as possible. The ROP is a
function of a
number of variables, including the rotational speed of the drill bit and the
WOB.
[0006] Techniques have been developed to estimate the energy expended to
drill through a fixed volume of rock ¨ in other words, the ratio of the energy
input into
the drilling to the output of the drilling in terms of ROP ¨ which is referred
to as the
Specific Energy. One measure of the Specific Energy is the Mechanical Specific
Energy ("MSE"), which is a measure of the mechanical energy required to drill
through a fixed volume of formation, obtained by determining the ratio of the
rate of
the mechanical energy usage to the ROP. More recently, another measure of the
specific energy, referred to as the Hydro Mechanical Specific Energy ("HMSE")
has
been developed to take into account the hydraulic, as well as the mechanical,
energy
expended during drilling. Attempts have been made in the prior art to utilize
the
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specific energy, especially the MSE, to optimize drilling performance by
favoring
operation at conditions that will result in a low value of MSE. However,
depending
on the characteristics of the drilling operation, operating a minimum value of
MSE
does not uniformly result in maximizing drilling performance. Therefore, an
ongoing
need therefore exists for methods of optimizing drilling performance and
monitoring
the drilling performance on an on-going basis to determine whether drilling
conditions have changed, warranting further optimization.
Summary of the Invention
[0007] In one embodiment, the invention encompasses a method, which may
be computer implemented, of operating a drill string drilling into an earthen
formation
so as to form a bore hole using a drill bit, comprising the steps of: (a)
operating the
drill string at a plurality of different sets of drilling conditions during
which the drill
bit penetrates into the earthen formation by applying torque to the drill bit
so as to
rotate the drill bit and applying weight to the drill bit, wherein in a
preferred
embodiment each of the drilling conditions comprises the weight on the drill
bit and
the speed at which the drill bit rotates, the operation of the drill string
being
performed for a period of time at each of the sets of drilling conditions; (b)
determining the combination of the torque applied to the drill bit and the
rate at which
the drill bit penetrates into the earthen formation a selected number of times
over each
of the periods of time at which the drilling is performed at each of the sets
of drilling
conditions; (c) determining the value of ratio of the energy input into the
drilling to
the output in terms of ROP, and preferably the Specific Energy, and most
preferably
the Mechanical Specific Energy, from each of the combinations of torque and
rate of
penetration determined in step (b) for each of the sets of drilling
conditions; (d)
determining the variability, such as by calculating the standard deviation, in
the values
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of the ratio determined in step (c) for each of the sets of drilling
conditions; (e)
identifying the set of drilling conditions among the plurality of sets of
drilling
conditions for which the variability in the ratio is determined in step (d)
that yielded
the smallest variability; and (f) operating the drilling string at the set of
drilling
conditions identified in step (e).
[0008] The invention also encompasses a method of operating a drill string
drilling into an earthen formation so as to form a bore hole using a drill
bit,
comprising the steps of: (a) operating the drill string at a first set of
drilling conditions
during which the drill bit penetrates into the earthen formation by applying
torque to
the drill bit so as to rotate the drill bit and applying weight to the drill
bit, wherein the
first set of drilling conditions comprises the weight on the drill bit and the
speed at
which the drill bit rotates; (b) determining the combination of the torque
applied to the
drill bit and the rate at which the drill bit penetrates into the earthen
formation a
selected number of times while operating at the first set of drilling
conditions; (c)
determining the ratio of the energy input into the drilling to the output of
the drilling
in terms of ROP, and preferably the value of the Specific Energy, and most
preferably
the value of Mechanical Specific Energy, from each of the combinations of
torque and
rates of penetration determined in step (b); (d) determining the variability
in the
values of the ratio determined in step (c); (e) determining whether the
standard
deviation in the values of ratios determined in step (d) exceeds a
predetermined
threshold; (f) changing from the first set of drilling conditions to a second
set of
drilling conditions if the variability in the values of ratio determined in
step (d)
exceeds the predetermined threshold.
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Brief Description of the Drawings
[0009] The foregoing summary, as well as the following detailed description
of a preferred embodiment, are better understood when read in conjunction with
the
appended diagrammatic drawings. For the purpose of illustrating the invention,
the
drawings show embodiments that are presently preferred. The invention is not
limited, however, to the specific instrumentalities disclosed in the drawings.
[0010] Figure 1 is a view, partly schematic, of a drilling rig operated
according to the current invention.
[0011] Figure 2 is a graph of MSE versus WOB, in thousands of pounds, at
three drill bit rotary speeds ¨ 220 RPM. 240 RPM and 250 RPM. The data is
intended for illustrative purposes and is not intended to represent data from
an actual
drilling operation.
[0012] Figure 3 is a chart, based on actual data from a drilling operation,
showing the standard deviation in MSE versus WOB, in thousands of pounds, at
drill
bit rotary speeds of 220 RPM. 240 RPM and 250 RPM.
[0013] Figure 4 is a flow chart illustrating a method of optimizing drilling
according to the current invention.
[0014] Figure 5 is a flow chart illustrating a method of monitoring drilling
according to the current invention.
Description of Preferred Embodiments
[0015] As shown in Figure 1, drill rigs typically comprise a derrick 9 that
supports a drill string 4. A drill bit 8 is coupled to the distal end of a
bottomhole
assembly 6 of the drill string 4. A prime mover (not shown), such as a top
drive or
rotary table, rotates the drill string 4 so as to control the rotational speed
("RPM") of,
and torque on, the drill bit 8. As is conventional, a pump 10 pumps a fluid 14
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typically referred to as drilling mud -- downward through an internal passage
in the
drill string. After exiting at the drill bit 8, the returning drilling mud 16
flows upward
to the surface through an annular passage formed between the drill string 4
and the
bore hole 2 in the earthen formation 3. A mud motor 40, such as a helicoidal
positive-
displacement pump -- sometimes referred to as a "Moineau-type" pump -- may be
incorporated into the bottomhole assembly 6 and is driven by the flow of
drilling mud
14 through the pump.
[0016] According to the current invention, the values of WOB, drill bit
RPM, ROP and torque on bit ("TOB") are determined and varied. Instrumentation
and methods for determining WOB, RPM, ROP, TOB are described in U.S.
Application serial no. 12/698,125, filed February 1, 2010, entitled "System
and
Method for Monitoring and Controlling Underground Drilling," hereby
incorporated
by reference in its entitery. Although various methods and instrumentation are
described below for obtaining such values, other methods and instrumentation
could
also be utilizes.
[0017] Downhole strain gauges 7 may be incorporated into the bottomhole
assembly 6 to measure the WOB. A system for measuring WOB using downhole
strain gauges is described in U.S. Patent No. 6,547,016, entitled "Apparatus
For
Measuring Weight And Torque An A Drill Bit Operating In A Well," hereby
incorporated by reference herein in its entirety. In addition to downhole
sensors
measuring the WOB, downhole sensors, such as strain gauges, measuring the
torque
on bit ("TOB") and the bending on bit ("BOB") are also included in the
bottomhole
assembly. Techniques for downhole measurement of TOB are also described in the
aforementioned U.S. Patent No. 6,547,016, incorporated by reference above.
Techniques for the downhole measurement of BOB are described in U.S.
Application
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Serial No. 12/512,740, filed July 30, 2009, entitled "Apparatus for Measuring
Bending on a Drill Bit Operating in a Well," hereby incorporated by reference
in its
entirety. A sub incorporating WOB, TOB and BOB sensors is referred to as a
"WTB
sub."
[0018] A magnetometer 42 is incorporated into the bottomhole assembly 6
that measures the instantaneous rotational speed of the drill bit 8, using,
for example,
the techniques in U.S. Patent Application Publication No. 2006/0260843, filed
May 1,
2006, entitled "Methods And Systems For Determining Angular Orientation Of A
Drill String," hereby incorporated by reference herein in its entirety.
[0019] As is conventional, the WOB is controlled by varying the hook load
on the derrick 9. A top sub 45 is incorporated at the top of the drill string
and
encloses strain gauges 48 that measure the axial (hook) load, as well as the
bending
and torsional load on the top sub, as is a triaxial accelerometer 49 that
senses vibration
of the drill string. Using techniques well known in the art, the WOB can be
calculated
from the hook load measured by the strain gauges in the top sub, for example,
by
subtracting the frictional resistance acting on the drill string from the
measured hook
load. The value of the frictional resistance can be obtained by pulling up on
the drill
string so that the drill bit is no longer contacting the formation and noting
the change
in the hook load. In a wired pipe, the data from the downhole sensors would be
received by the top sub 45. The data from the top sub 45 strain gauges, as
well as the
downhole sensors in a wired pipe system, can be transmitted via wireless
telemetry to
the surface acquisition system 12, using the technique disclosed in U.S.
Application
Serial No. 12/389,950, filed February 20, 2009, entitled "Synchronized
Telemetry
From A Rotating Element," hereby incorporated by reference in its entirety, so
that
certain parameters, such asWOB, can be determined at the surface.
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[0020] Preferably, the surface monitoring system also includes a hook load
sensor 30 for determining WOB. The hook load sensor 30 measures the hanging
weight of the drill string, for example, by measuring the tension in the draw
works
cable using a strain gauge. The cable is run through three supports. The
supports put
a known lateral displacement on the cable. The strain gauge measures the
amount of
lateral strain due to the tension in the cable, which is then used to
calculate the axial
load. A sensor 32 is also used for sensing drill string rotational speed.
[0021] The drilling operation according to the current invention also
includes a mud pulse telemetry system, which includes a mud pulser 5
incorporated
into the downhole assembly 6. Using techniques well known in the art, the mud
pulse
telemetry system encodes data from downhole sensors and, using the pulser 5,
transmits the coded pulses to the surface. Mud pulse telemetry systems are
described
more fully in U.S. Patent No. 6,714,138, entitled "Method And Apparatus For
Transmitting Information To The Surface From A Drill String Down Hole In A
Well," U.S. Patent No. 7,327,634, entitled "Rotary Pulser For Transmitting
Information To The Surface From A Drill String Down Hole In A Well," and U.S.
Patent Application Publication No. 2006/0215491, entitled "System And Method
For
Transmitting Information Through A Fluid Medium," each of which is
incorporated
by reference herein in its entirety.
[0022] As is also conventional, a data acquisition system 12 at the surface
senses pressure pulsations in the drilling mud 14 created by the mud pulser 5
that
contain encoded information from a vibration memory module and other sensors
in
the bottomhole assembly 6. The data acquisition system 12 decodes this
information
and transmits it to a computer processor 18, also preferably located at the
surface.
Data from the surface sensors, such as the hook load sensor 30, the drill
string
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rotational speed sensor 32, and a ROP sensor 34 are also transmitted to the
processor
18.
[0023] Software 20 for performing the methods described herein, discussed
below, is preferably stored on a non-transitory computer readable medium, such
as a
CD, and installed into the processor 18 that executes the software so as to
perform the
methods and functions discussed below. The processor 18 is preferably
connected to
a display 19, such as a computer display, for providing information to the
drill rig
operator. A data entry device 22, such as a keyboard, is also connected to the
processor 18 to allow data to be entered for use by the software 20. A memory
device
21 is in communication with the processor 18 so that the software can send
data to,
and receive data from, storage when performing its functions. The processor 18
may
be a personal computer that preferably has at least a 16X CD-ROM drive, 512 MB
RAM, 225 MB of free disk space, a graphics card and monitor capable of 1024 x
786
or better at 256 colors and running a Windows XPTM operating system. Although
the processor 18 executing the software 20 of the current invention is
preferably
located at the surface and can be accessed by operating personnel, portions of
the
software 20 could also be installed into a processor located in the bottomhole
assembly so that some of the operations discussed below could be performed
downhole.
[0024] According to the current invention, the Specific Energy is used to
determine the most effective set of drilling parameters, in particular the
optimum
WOB and drill bit RPM. Preferably, the MSE is used as a measure of the
Specific
Energy. The MSE can be calculated, for example, as described in F. Dupriest &
W.
Koederitz, "Maximizing Drill Rates With Real-Time Surveillance of Mechanical
Specific Energy," SPE/IADC Drilling Conference, SPE/IADC 92194 (2005) and W.
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Koederitz & J. Weis, "A Real-Time Implementation Of MSE," American Association
of Drilling Engineers, AADE-05-NTCE-66 (2005), each of which is hereby
incorporated by reference in its entirety. Specifically, the MSE may be
calculated
from the equation:
MSE = [(480 x TOB x RPM)/(D2 x ROP)] + [(4 x WOB)/(D2 x3r)]
Where:
MSE = Mechanical Specific Energy
TOB = torque applied to the drill bit, ft-lb
RPM = rotational speed of the drill bit
ROP = rate of penetration, ft/hr
WOB = weight on bit, lb
D = diameter of drill bit, inches
[0025] Alternatively, the HMSE may be used. The HMSE can be
calculated, for example, as described in K. Mohan & F. Adil, "Tracking
Drilling
Efficiency Using Hydro-Mechanical Specific Energy, SPE/IADC Drilling
Conference, SPE/IADC 119421 (2009), herein incorporated by reference in its
entirety. Specifically, the HMSE may be calculated from the equation:
HMSE = [(WOB x FJ)/Ab] + [(120 r x RPM x TOB + 1154 ri x 4Pb x Q)/(Ab x ROP)]
Where:
HMSE = Hydro Mechanical Specific Energy
TOB = torque applied to the drill bit, ft-lb
RPM = rotational speed of the drill bit
ROP = rate of penetration, ft/hr
WOB = weight on bit, lb
Ab = area of the drill bit, inches2
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Fj = impact force exerted by the fluid on the formation, lb
Q = Flow rate, gallons/minute
= dummy factor for energy reduction
APb = pressure drop across the bit, psi
[0026] According to conventional thinking, drilling should be conducted at
the operating conditions that yield the lowest value of Specific Energy.
However,
surprisingly, the inventor has discovered that optimal drilling occurs at the
operating
conditions at which the scatter in the value of Specific Energy over time is a
minimum, which are not necessarily the same operating conditions as those that
yield
the lowest value of Specific Energy.
[0027] The scatter in the values of Specific Energy over time may be
quantified by, for example calculating the standard deviation in Specific
Energy. The
operating conditions that may be varied to determine optimum drilling may be,
for
example, drill bit RPM and WOB.
[0028] The method of operating a drill string according to the current
invention can be illustrated by reference to Figure 2, which is a graph of
MSE,
calculated as explained above, at four values of WOB (6,000 lbs, 12,000 lbs,
14,000
lbs and 17,000 lbs) and three drill bit rotary speeds (220 RPM. 240 RPM and
250
RPM). A number of readings are taken at each combination of WOB and RPM. Best
fit curves of the data at each RPM are shown on the graph. According to
conventional thinking, the operating condition for optimal drilling, based on
an
assessment of the value of MSE, would be 12,000 lbs WOB and perhaps 240 RPM,
since this set of operating conditions yields the lowest value of MSE.
However,
according to the current invention, operation at these conditions would not be
optimal.
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Rather, a WOB of 14,000 lbs should be used because the scatter in MSE over
time is
less at this WOB than at 12,000 lbs.
[0029] Figures 3 and 4 show the results of actual data from a drilling
operation in which data was taken of TOB and ROP at six different sets of
operating
conditions ¨ 6,000 lbs WOB at 240 RPM and 250 RPM, 10,000 lbs at 240 RPM and
250 RPM, and 14,000 lbs at 220 RPM and 240 RPM. Measurements of WOB, RPM,
TOB and ROP were taken every 1 second over a period of about 15 to 30 minutes
at
each operating condition and average MSE and standard deviation in MSE over 5 -
10
minute periods were determined. As shown in Figure 3, the lowest average MSE
occurred at 10,000 lbs and 250 RPM, although the average MSE at 14,000 lbs and
either 220 RPM and 240 ROM was only slightly higher, indicating that operation
at
any of these three sets of operating conditions would result in optimal
drilling.
However, as shown in Figure 4, consideration of the standard deviation in MSE
at
each operating condition reveals that the variation in MSE is lowest at 14,000
lbs and
220 RPM, indicating that, according to the current invention, operating at
this set of
conditions will result in optimal drilling.
[0030] Figure 5 is a flow chart illustrating one embodiment of a method for
optimizing drilling according to the current invention. In step 100, values
for
variables N, M, P and 0 are set to zero. In step 105, the WOB at which the
drill string
is operated is increased, as discussed above, by an amount AWOB. In step 110,
the
RPM is increased by an amount ARPM. In step 115, the TOB and ROP are measured.
In step 120, the MSE is calculated, using the equation discussed above using
the
measured values of RPM, WOB, TOB and the diameter of the drill bit. Using
counter
130, steps 115 and 120 are repeated so that TOB and ROP are measured and MSE
is
calculated N1 +1 different times at the initial values of RPM and WOB. In step
135
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the average value of MSE and ROP, as well as the standard deviation in MSE,
are
determined from the N1 +1 sets of data obtained at the initial values of WOB
and
RPM.
[0031] Using counter 145, steps 110 to 135 are repeated for M1 +1 different
values of RPM. Using counter 150, steps 105 through 135 are repeated for P1 +1
values of WOB.
[0032] For example, the initial value of WOB might be set at 0 and WOB
varied from 2000 lbs to 18,000 lbs in 2000 lb increments (AWOB = 2000, P1 = 8)
so
that data was obtained at nine different WOB' s. The initial value of RPM
might be
set at 200 RPM and RPM varied from 200 RPM to 300 RPM in 20 RPM increments
(ARPM = 20, M1 = 5) so that data was obtained at six different RPM's at each
of the
nine WOB' s so that the total number of different operating conditions was
fifty four.
Average values of MSE and ROP and the standard deviation in MSE could be
calculated every second for 10 minutes at each set of WOB and RPM (N1 = 600)
so
that a total of 32,400 sets of data were obtained.
[0033] After values of average ROP and MSE and the standard deviation in
MSE have been determined at each set of operating conditions ¨ that is, at
each
combination of WOB and RPM ¨ the values of WOB and RPM that will yield
optimum drilling according to the current invention are selected in step 160.
In one
embodiment, the selected values of WOB and RPM are those at which the standard
deviation in MSE is a minimum. Further, if the standard deviation in MSE at
two or
more operating points were within a predetermined range, such as within 5% of
each
other, the set of operating conditions among those conditions that yielded the
highest
ROP would be selected. If the ROP among the sets of operating conditions at
which
the standard deviation was within a predetermined range was also within a
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predetermined range, such as 5% of each other, the set of operating conditions
among
these conditions that yielded the lowest average MSE is selected. Thus,
although the
operating condition at which the standard deviation in MSE is clearly lowest
is
preferably selected, if two or more operating conditions yield essentially the
same
value of MSE, then ROP is used as the tie breaker. If two or more operating
conditions yield essentially the same values of both the standard deviation in
MSE
and ROP, then average MSE is used as the tie breaker.
[0034] In performing steps of the drilling optimization method discussed
above, the different operating conditions could be set, and the calculations
done,
manually by the operator, or some or all of the steps could be programmed in
software, using well known techniques, and automatically performed under
direction
from the processor 18.
[0035] Figure 6 is a flow chart illustrating one embodiment of a method of
monitoring drilling according to the current invention. In step 200, values of
WOB,
TOB, RPM and ROP are obtained, with the values of WOB and RPM having
preferably been obtained by the drilling optimization method discussed above.
In step
210, the MSE at these operating conditions is determined, using the equation
discussed above. These steps are repeated until, in step 220, a determination
is made
as to whether a sufficient number of data points have been obtained to
calculate the
standard deviation in MSE. For example, values of MSE might be calculated
every
one second for 10 minutes and the standard deviation is calculated from these
600
values of MSE. After a sufficient number of data points have been taken the
standard
deviation in MSE is calculated in step 230, as well as the average value of
MSE. In
step 240, the average value of MSE is compared to a parameter A and the
standard
deviation is compared to a second parameter B. No remedial action would be
taken if
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in step 250 both the average MSE was less than A and the standard deviation in
MSE
were less than B. The parameters A and B may be determined from experience by,
for example, using the following equations:
A = MSEAvG + K x 6MSE
B = L x GMSE
[0036] Where K and L are constants selected based on experience in
operating the drill string and MSEAvG and GmsE are the average MSE and
standard
deviation in MSE obtained at the operating conditions selected based on a
drilling
optimization test, such as the method discussed above in connection with
Figure 5.
For example, K might be set to K=1 and L set to L=3 so that optimum drilling
would
be deemed to still be obtained if, during normal operation both (i) the
average MSE
over a predetermined time interval was less than the sum of average value of
MSE
and the standard deviation in MSE, as obtained at the optimum conditions by
the
drilling optimization test, and (ii) the standard deviation in MSE over the
predetermined time interval was less than three times the standard deviation
in MSE
obtained at the optimum conditions by the drilling optimization test.
[0037] If the conditions in step 240 are not satisfied, then step 250
determines whether, although the average value of MSE exceeded the criteria,
the
standard deviation in MSE satisfied the criteria. If so, in step 260 the
operator is
advised that it is likely that drill bit has entered into a formation with
different
characteristics, for example, from hard rock to softer rock, but that smooth
drilling
was still being obtained. In step 270, the drilling optimization would be re-
run and a
new set of optimum drilling conditions (e.g., WOB and RPM) would be obtained
and
the drilling monitoring re-commenced at the new conditions.
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[0038] If in step 280 it were determined that both the average value of MSE
and the standard deviation in MSE exceeded their criteria -- in other words,
the
average energy used in drilling had significantly increased as well as the
variability in
the drilling energy -- then in step 290 steps 200 to 230 are repeated and a
determination is made as to whether the values for average MSE and the
standard
deviation in MSE have returned to normal ¨ that is, the both the average MSE
is again
less than A and the standard deviation in MSE is again less than B. If both
the
average MSE and the standard deviation in MSE now meet criteria in step 290,
in
other words, step changes are occurring in the drilling so that acceptable
drilling is
being obtained some of the time but unacceptable drilling at other times, then
the
operator is notified in step 300 that it is likely that the bit is drilling
through stringers
in the formation. In step 270, the drilling optimization test is re-run and a
new set of
optimum drilling conditions (e.g., WOB and RPM) are obtained and the drilling
monitoring re-commenced at the new conditions, using the average MSE and
standard
deviation in MSE determined during the repeat of the drilling test to obtain
the criteria
used in step 240.
[0039] If in step 290, either the average MSE or the standard deviation in
MSE still did not meet the criteria ¨ in other words, the repeat of steps 200
to 230
yield values for average MSE and the standard deviation in MSE that still do
not meet
the criteria -- then the drilling optimization test is re-run in step 310 and
a new set of
optimum drilling conditions (e.g., WOB and RPM) are obtained. In step 320 it
is
determined whether the average MSE and standard deviation in MSE obtained from
the re-run drilling optimization test are sufficiently close to that obtained
during the
prior drilling optimization test, for example, using the criteria A and B as
discussed
above for step 240. If the values are sufficiently close, then monitoring is
resumed
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using the average MSE and standard deviation in MSE determined during the
repeat
of the drilling optimization test in step 310 is used to obtain the criteria
applied in step
240.
[0040] If either the average MSE or the standard deviation in MSE
determined during the repeat of the drilling test in step 310 exceeds the
predetermined
criteria previously discussed ¨ in other words, the average MSE and standard
deviation in MSE are considerably higher than they previously were even at the
operating conditions determined to be optimal in the repeat of the drilling
optimization test -- then in step 330 the operator is advised that the drill
bit or bottom
hole assembly may have become damaged that the drill string should be removed
from the bore hole, referred to as "tripping," to allow inspection of the
equipment.
Again, the method of monitoring the drilling can be performed manually by the
operator, or some or all of the steps could be programmed in software, using
well
known techniques, and automatically performed under direction of the processor
18.
[0041] The methods of the current invention enhance the utilization of MSE
by analyzing the data scatter over a given period of time. The data scatter
analysis
provides a clear insight for identifying the drilling parameters that offer
the best
drilling efficient over a wide range of drilling conditions. Also, the bit
condition can
be monitored using MSE. By monitoring the change and scatter over time it can
be
seen how fast the bit is deteriorating. The information can also be used to
take
corrective action to extend the bit life. Further, the MSE calculations can be
used to
see changes in formations at the bit much earlier than with gamma and
resistivity tool.
[0042] The ideal situation occurs when both the MSE value and the
variability in MSE are minimized. When this condition occurs the drilling is
optimized and stable, able to withstand a wide range of drilling conditions.
Ideally
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the operator would vary the drilling parameters to identify the condition at
which the
standard deviation is a minimum and, if the standard deviation is comprable at
more
than one set of conditions, the operator can determined the conditions as
which the
value of MSE is a minimum. An increase in MSE, and more significantly, an
incease
in the variability in MSE, indicates that the drilling conditions downhole
have
changed and the drilling parameters may need adjusting to once again optimize
the
drilling.
[0043] Tracking MSE also allows the condition of the bit to be monitored.
Under normal drilling conditions the MSE will gradually increase to increased
depth,
increased compressive rock strength and normal bit wear. When the bit is
exposed to
harsher drilling conditions the slope of the MSE line increases as the bit
experiences
accelerated wear. As the bit degrades even further the slope continues to
increase and
becomes more erratic, resulting in an increase in the variability in MSE.
[0044] The MSE may also be used to determine the locations of formations
well ahead of gamma and resistivity measurements. The MSE value changes with
changes in formation strengths. Higher strength formations yield higher MSE
values.
Additionally, as the bit drills through stringers the MSE values jump around
producing large variability in MSE. When the ROP is low, monitoring MSE may
indicate the change in formation hours ahead of gamma and resistivity tools.
[0045] Although the invention has been described with reference to specific
methodologies for optimizing drilling, the invention is applicable to other
methodologies based on the teachings herein. For example, operating conditions
other than WOB and RPM may be varied to determine the optimum drilling
conditions. Although the invention has been described in detail with reference
to
measurements of MSE, other measures of Specific Energy, such as HMSE, may be
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used. Accordingly, the present invention may be embodied in other specific
forms
without departing from the spirit or essential attributes thereof and,
accordingly,
reference should be made to the appended claims, rather than to the foregoing
specification, as indicating the scope of the invention.
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